Acid gas removal from gas streams, and especially removal of hydrogen sulfide and carbon dioxide from gas streams formed in oil/production facilities, refinery process units, and/or synthesis gas production plants is required to avoid release of the acid gas into the environment. Most commonly, the bulk of the sulfur content is converted in a processing unit into elemental sulfur or other commodities (e.g., sulfuric acid, sodium bi-sulfate, etc.), while the tail gas of such processing units is further treated to reduce its sulfur content before venting to the atmosphere.
Among other known processes, acid gases are most typically removed using an amine-based solvent to absorb the acid gas via various chemical reactions to thereby produce a rich amine solvent, which is then regenerated using heat. Exemplary aspects of gas purification using amine solvents are taught in the “Fifth Edition Gas Purification” by Arthur Kohl and Richard Nielsen (Gulf Publishing, 1960 to 1997). Particularly preferred amine-based solvents include secondary and tertiary amines (e.g., diethanolamine [DEA], and/or methyldiethanol-amine [MDEA]), which are generally more energy efficient than primary amines due to their lower heat of reaction and lower energy requirements for regeneration. Further known amines also include monoethanolamine [MEA], diglycolamine [DGA], triethanolamine [TEA], diisopropylamine, and various combinations thereof, which may still further comprise one or more additives.
The effectiveness of a particular amine solvent to absorb acid gases to meet the treated gas specification typically depends on the residual acid gas content in the lean amine, which in turn is a function of the particular regeneration method and conditions. The lower the acid gas content in the lean amine, the more effective is the acid gas absorption process to achieve the desirable result in the treated gas. Unfortunately, the energy demand for heating and cooling processes in the amine regeneration unit significantly increases with decreasing residual acid gas content in the lean amine. Therefore, numerous approaches have been undertaken to improve the current acid gas absorption and regeneration processes.
For example, Dingman, et al. describe in U.S. Pat. No. 6,071,484 a method to produce an ultra lean amine using an ion exchange bed to remove the residual acid gases in the lean amine. While such a process reduces steam consumption in the regenerator reboiler, various new disadvantages arise. Most significantly, ion exchange resins are relatively expensive and need to be regenerated or replaced, and where regeneration is preferred, regeneration transfers the acid gas only from one place to another. In yet another example, as described in U.S. Pat. No. 4,798,910 to Herrin, the inventor uses an additional heat exchanger to heat the rich amine solvent using a portion of the heat content in the regenerator overhead gases. While such a method advantageously reduces the overhead condenser duty to at least some degree, reboiler duty remains largely unaffected, as the amine regeneration process is more strongly dependent on the stripping steam supplied at the bottom of the regenerator.
Still further configurations and methods for amine absorption and regeneration are disclosed in U.S. Pat. No. 3,565,573 to Thirkell in which acid gas is treated in a dual-zone absorber to provide a rich solvent that is regenerated in conventional manner. Similarly, Green et al. describe in U.S. Pat. No. 3,829,521 a configuration in which a pre-stripper and a stripper operate in series to remove acid gas from two gas streams. While such configurations and methods improve gas treatment in at least some respect, other problems remain. Most significantly, deep removal of acid gases to meet a stringent treated gas specification (e.g., less than 10 ppmv) is typically not achievable, or uneconomic due to the expense of relatively high energy costs in the operation of the regenerator or regenerators.
In addition to the problems associated with the energy demand of amine regeneration, condensation and foaming of heavy hydrocarbons and aromatics in the absorber often renders gas treatment ineffective, and may even cause column instability and/or flooding. To avoid such unstable situation, the absorber can be operated at a higher temperature to avoid the feed gas from dropping below its dew point temperature inside the absorber. Higher temperature operation is often achieved using a higher lean amine temperature. However, a higher lean amine temperature renders hydrogen sulfide absorption less effective due to less favorable amine-hydrogen sulfide equilibrium conditions, which is particularly problematic in low pressure units where the partial pressure of H2S is much lower and less favorable (e.g., to treat tail gas of a sulfur plant).
Still further, process integration often leads to plant configurations in which a single source of lean amine is used to supply all process units. While integration often simplifies the amine regeneration operation, integration is frequently not energy efficient as lean amine loadings typically vary among different process units. For example, a hydrotreater unit, which operates at high pressure with less stringent treating requirement can accept a lean amine with a higher lean amine loading (typically 0.01 or higher mole of H2S to mole of amine), while a tail gas treating unit must often use a very lean amine (typically 0.005 or lower mole of H2S to mole of amine) to meet the emission requirement. Thus, use of a single source of lean amine designed for the more demanding treating requirement results in over-stripping for the less demanding units. This is particularly problematic when an existing facility is expanded to include more demanding units such as the tail gas treatment unit, which would require upgrading the entire amine regeneration system. Consequently, and especially where stringent emission specifications are encountered, currently known methods and configurations are often neither adequate, nor energy efficient/economical in operation.
Thus, while numerous compositions and methods for acid gas absorption and solvent regeneration are known in the art, all or almost all of them, suffer from one or more disadvantages. Therefore, there is still a need for improved configurations and methods for acid gas absorption and solvent regeneration.